APC 2015 2Q - 10Q - SEC · Title: APC 2015 2Q - 10Q Created Date: 7/28/2015 1:50:00 PM

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UNITED STATESSECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q(Mark One)

[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2015 or

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 1-8968

ANADARKO PETROLEUM CORPORATION(Exact name of registrant as specified in its charter)

Delaware 76-0146568(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)

1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046(Address of principal executive offices)

Registrant’s telephone number, including area code (832) 636-1000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer Accelerated filer Non-accelerated filer Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No

The number of shares outstanding of the Company’s common stock at June 30, 2015, is shown below:

Title of Class Number of Shares OutstandingCommon Stock, par value $0.10 per share 508,012,188

TABLE OF CONTENTS

PART I PageItem 1. Financial Statements

Consolidated Statements of Income for the Three and Six Months Ended June 30, 2015 and 2014

Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2015 and 2014

Consolidated Balance Sheets at June 30, 2015, and December 31, 2014

Consolidated Statement of Equity for the Six Months Ended June 30, 2015

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014

Notes to Consolidated Financial Statements

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Item 4. Controls and Procedures

PART II

Item 1. Legal Proceedings

Item 1A. Risk Factors

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Item 6. Exhibits

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See accompanying Notes to Consolidated Financial Statements.

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PART I. FINANCIAL INFORMATIONItem 1. Financial Statements

ANADARKO PETROLEUM CORPORATIONCONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

Three Months Ended

June 30,Six Months Ended

June 30,millions except per-share amounts 2015 2014 2015 2014Revenues and OtherNatural-gas sales $ 487 $ 991 $ 1,128 $ 2,208Oil and condensate sales 1,616 2,705 3,035 5,129Natural-gas liquids sales 229 411 461 797Gathering, processing, and marketing sales 305 278 598 589Gains (losses) on divestitures and other, net (1) 54 (265) 1,560Total 2,636 4,439 4,957 10,283Costs and ExpensesOil and gas operating 226 273 522 586Oil and gas transportation and other 289 281 650 547Exploration 103 502 1,186 801Gathering, processing, and marketing 255 250 509 502General and administrative 278 305 588 603Depreciation, depletion, and amortization 1,214 1,048 2,470 2,172Other taxes 151 361 333 675Impairments 30 117 2,813 120Deepwater Horizon settlement and related costs — 93 4 93Total 2,546 3,230 9,075 6,099Operating Income (Loss) 90 1,209 (4,118) 4,184Other (Income) ExpenseInterest expense 201 186 417 369(Gains) losses on derivatives, net (311) 323 (159) 776Other (income) expense, net 15 (13) 62 (12)Tronox-related contingent loss — 19 5 4,319Total (95) 515 325 5,452Income (Loss) Before Income Taxes 185 694 (4,443) (1,268)Income tax expense (benefit) 77 428 (1,315) 1,092Net Income (Loss) 108 266 (3,128) (2,360)Net income attributable to noncontrolling interests 47 39 79 82Net Income (Loss) Attributable to Common Stockholders $ 61 $ 227 $ (3,207) $ (2,442)

Per Common ShareNet income (loss) attributable to common stockholders—basic $ 0.12 $ 0.45 $ (6.32) $ (4.84)Net income (loss) attributable to common stockholders—diluted $ 0.12 $ 0.45 $ (6.32) $ (4.84)Average Number of Common Shares Outstanding—Basic 508 505 507 505Average Number of Common Shares Outstanding—Diluted 509 507 507 505Dividends (per common share) $ 0.27 $ 0.27 $ 0.54 $ 0.45

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ANADARKO PETROLEUM CORPORATIONCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended June 30,

Six Months Ended June 30,

millions 2015 2014 2015 2014Net Income (Loss) $ 108 $ 266 $ (3,128) $ (2,360)Other Comprehensive Income (Loss)

Adjustments for derivative instrumentsReclassification of previously deferred derivative losses to

(gains) losses on derivatives, net 3 3 5 5Income taxes on reclassification of previously deferred

derivative losses to (gains) losses on derivatives, net (1) (1) (2) (2)Total adjustments for derivative instruments, net of taxes 2 2 3 3Adjustments for pension and other postretirement plans

Amortization of net actuarial (gain) loss to general andadministrative expense 13 7 26 14

Income taxes on amortization of net actuarial (gain) loss togeneral and administrative expense (5) (3) (9) (5)

Amortization of net prior service (credit) cost to general andadministrative expense 1 — 1 —

Total adjustments for pension and other postretirement plans, netof taxes 9 4 18 9

Total 11 6 21 12Comprehensive Income (Loss) 119 272 (3,107) (2,348)Comprehensive income attributable to noncontrolling interests 47 39 79 82Comprehensive Income (Loss) Attributable to Common

Stockholders $ 72 $ 233 $ (3,186) $ (2,430)

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ANADARKO PETROLEUM CORPORATIONCONSOLIDATED BALANCE SHEETS

(Unaudited)

millionsJune 30,

2015December 31,

2014ASSETSCurrent AssetsCash and cash equivalents $ 2,173 $ 7,369Accounts receivable (net of allowance of $6 million and $7 million)

Customers 1,028 1,118Others 1,574 1,409

Other current assets 635 1,325Total 5,410 11,221Properties and EquipmentCost 75,608 75,107Less accumulated depreciation, depletion, and amortization 37,788 33,518Net properties and equipment 37,820 41,589Other Assets 2,474 2,310Goodwill and Other Intangible Assets 6,420 6,569Total Assets $ 52,124 $ 61,689

LIABILITIES AND EQUITYCurrent LiabilitiesAccounts payable $ 3,034 $ 3,683Current asset retirement obligations 267 257Accrued expenses 1,244 994Short-term debt 33 —Deepwater Horizon settlement and related costs 91 90Tronox-related contingent liability — 5,210Total 4,669 10,234Long-term Debt 16,025 15,092Other Long-term LiabilitiesDeferred income taxes 7,594 9,249Asset retirement obligations 1,714 1,796Other 2,763 3,000Total 12,071 14,045

EquityStockholders’ equityCommon stock, par value $0.10 per share

(1.0 billion shares authorized, 527.7 million and 525.9 million shares issued) 52 52Paid-in capital 9,169 9,005Retained earnings 8,641 12,125Treasury stock (19.7 million and 19.3 million shares) (977) (940)Accumulated other comprehensive income (loss) (496) (517)Total Stockholders’ Equity 16,389 19,725Noncontrolling interests 2,970 2,593Total Equity 19,359 22,318Total Liabilities and Equity $ 52,124 $ 61,689

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ANADARKO PETROLEUM CORPORATIONCONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

Total Stockholders’ Equity

Common

StockPaid-inCapital

RetainedEarnings

TreasuryStock

Accumulated Other

ComprehensiveIncome (Loss)

Non-controllingInterests

TotalEquity

millions Balance at December 31, 2014 $ 52 $ 9,005 $ 12,125 $ (940) $ (517) $ 2,593 $ 22,318

Net income (loss) — — (3,207) — — 79 (3,128)Common stock issued — 105 — — — — 105Dividends—common stock — — (277) — — — (277)Repurchase of common stock — — — (37) — — (37)Subsidiary equity transactions — 59 — — — 85 144Issuance of tangible equity units — — — — — 348 348Distributions to noncontrolling

interest owners — — — — — (135) (135)Reclassification of previously

deferred derivative losses to(gains) losses on derivatives, net — — — — 3 — 3

Adjustments for pension and otherpostretirement plans — — — — 18 — 18

Balance at June 30, 2015 $ 52 $ 9,169 $ 8,641 $ (977) $ (496) $ 2,970 $ 19,359

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ANADARKO PETROLEUM CORPORATIONCONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended

June 30,millions 2015 2014Cash Flows from Operating ActivitiesNet income (loss) $ (3,128) $ (2,360)Adjustments to reconcile net income (loss) to net cash provided by (used in)

operating activitiesDepreciation, depletion, and amortization 2,470 2,172Deferred income taxes (1,187) 188Dry hole expense and impairments of unproved properties 1,040 609Impairments 2,813 120(Gains) losses on divestitures, net 425 (1,468)Total (gains) losses on derivatives, net (158) 786Operating portion of net cash received (paid) in settlement of derivative instruments 172 (186)Other 74 108Changes in assets and liabilities

Deepwater Horizon settlement and related costs 1 92Tronox-related contingent liability (5,210) 4,319(Increase) decrease in accounts receivable (105) (183)Increase (decrease) in accounts payable and accrued expenses (199) 21Other items—net (269) (27)

Net cash provided by (used in) operating activities (3,261) 4,191Cash Flows from Investing ActivitiesAdditions to properties and equipment and dry hole costs (3,501) (5,100)Acquisition of businesses (3) (4)Divestitures of properties and equipment and other assets 700 3,286Other—net 19 (282)Net cash provided by (used in) investing activities (2,785) (2,100)Cash Flows from Financing ActivitiesBorrowings, net of issuance costs 4,787 1,077Repayments of debt (3,857) (1,255)Financing portion of net cash received (paid) for derivative instruments (77) (222)Increase (decrease) in outstanding checks (109) 178Dividends paid (277) (230)Repurchase of common stock (37) (35)Issuance of common stock, including tax benefit on share-based compensation awards 19 73Sale of subsidiary units 187 92Issuance of tangible equity units — equity component 348 —Distributions to noncontrolling interest owners (135) (102)Net cash provided by (used in) financing activities 849 (424)Effect of Exchange Rate Changes on Cash 1 —Net Increase (Decrease) in Cash and Cash Equivalents (5,196) 1,667Cash and Cash Equivalents at Beginning of Period 7,369 3,698Cash and Cash Equivalents at End of Period $ 2,173 $ 5,365

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ANADARKO PETROLEUM CORPORATIONNOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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1. Summary of Significant Accounting Policies

General Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of natural gas, oil, condensate, natural gas liquids (NGLs), and the anticipated production of liquefied natural gas (LNG). In addition, the Company engages in the gathering, processing, treating, and transporting of natural gas, oil, and NGLs. The Company also participates in the hard-minerals business through royalty arrangements. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

Basis of Presentation The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s consolidated financial statements. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves; the value of properties and equipment; goodwill; intangible assets; asset retirement obligations; litigation liabilities; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Recently Issued Accounting Standards The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-03, Interest—Imputation of Interest (Subtopic 853-30)—Simplifying the Presentation of Debt Issuance Costs. This ASU will simplify the presentation of debt issuance costs by requiring such costs to be presented in the balance sheet as a reduction from the corresponding debt liability rather than as an asset. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective approach, with early adoption permitted. The Company does not expect the adoption to have a material impact on its consolidated financial statements.

The FASB issued ASU 2015-02, Consolidation—Amendments to the Consolidation Analysis. This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

The FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using one of two retrospective application methods, with early adoption permitted in 2017. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

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2. Acquisitions, Divestitures, and Assets Held for Sale

Acquisitions In November 2014, Western Gas Partners, LP (WES), a publicly traded consolidated subsidiary, acquired Nuevo Midstream, LLC (Nuevo) for $1.554 billion. Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC (DBM). The acquisition constitutes a business combination and was accounted for using the acquisition method of accounting. The fair-value measurements of the assets acquired and liabilities assumed at the acquisition date were preliminary as of June 30, 2015, pending final review of certain support related to the acquired entity’s assets and liabilities. There were no material changes to the fair value of assets acquired and liabilities assumed from the amounts included on the Company’s Consolidated Balance Sheet at December 31, 2014.

Divestitures and Assets Held for Sale For the six months ended June 30, 2015, the Company received $700 million in proceeds from divestitures and recognized net losses of $425 million primarily related to assets that were included in the oil and gas exploration and production reporting segment. The sale of certain enhanced oil recovery (EOR) assets in the Rocky Mountains Region (Rockies), with an original sales price of $703 million, closed in April 2015 for net proceeds of $686 million after closing adjustments. During the first quarter of 2015, these EOR assets satisfied criteria to be considered held for sale. These assets were remeasured to their then-current fair value using a market approach and Level 2 fair-value measurement, and the Company recognized a loss of $340 million.

During the second quarter of 2015, certain U.S. onshore oil and gas exploration and production properties and related midstream assets in East Texas satisfied criteria to be considered held for sale. These assets were remeasured to their fair value using a market approach and Level 2 fair-value measurement, and the Company recognized a loss of $97 million. Gains and losses on assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. The sale of these assets is expected to close in the third quarter of 2015 for a sales price of $440 million, subject to closing adjustments. At June 30, 2015, the Company’s Consolidated Balance Sheet included long-term assets of $440 million associated with assets held for sale.

3. Inventories

The following summarizes the major classes of inventories included in other current assets:

millionsJune 30,

2015December 31,

2014Oil $ 111 $ 133Natural gas 30 27NGLs 62 83Total inventories $ 203 $ 243

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4. Impairments

The following summarizes impairments of proved properties and the related post-impairment fair values by segment:

Three Months Ended Six Months Endedmillions Impairment Fair Value (1) Impairment Fair Value (1)

June 30, 2015Oil and gas exploration and production

Long-lived assets held for useU.S. onshore properties $ 4 $ 12 $ 2,303 $ 1,303Gulf of Mexico properties 17 — 25 —

Cost-method investment (2) 1 32 1 32Midstream

Long-lived assets held for use 8 199 484 202Total $ 30 $ 243 $ 2,813 $ 1,537

June 30, 2014Oil and gas exploration and production

Long-lived assets held for useGulf of Mexico properties $ 115 $ 327 $ 115 $ 327

Cost-method investment (2) 1 32 2 32Midstream

Long-lived assets held for use 1 — 3 —Total $ 117 $ 359 $ 120 $ 359

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(1) Measured as of the impairment date using the income approach and Level 3 inputs. (2) Represents the after-tax net investment.

Impairments during the six months ended June 30, 2015, were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties in the Rockies, which were impaired due to lower commodity prices. Impairments of proved properties are included in impairment expense in the Company’s Consolidated Statements of Income. During the second quarter of 2014, the Company impaired a Gulf of Mexico property due to a reduction in estimated future cash flows.

In addition to the proved property impairments above, the Company also recognized a $935 million impairment of unproved Greater Natural Buttes properties during the six months ended June 30, 2015, as a result of lower commodity prices. Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income.

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5. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $1.7 billion at June 30, 2015, and $1.5 billion at December 31, 2014. The increase in suspended exploratory well costs during 2015 is primarily related to the capitalization of costs associated with exploration drilling in the Gulf of Mexico and Mozambique. Projects with suspended exploratory well costs are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development and where management is actively pursuing efforts to assess whether reserves can be attributed to these projects. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time. During the six months ended June 30, 2015, no exploratory well costs previously capitalized as suspended exploratory well costs for greater than one year at December 31, 2014, were charged to dry hole expense.

6. Derivative Instruments

Objective and Strategy The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Henry Hub, Louisiana, for natural gas and Cushing, Oklahoma, or Sullom Voe, Scotland, for oil. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio increases (decreases) when interest rates increase (decrease).

The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. See Note 10—Accumulated Other Comprehensive Income (Loss).

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6. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are a combination of NYMEX West Texas Intermediate and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at June 30, 2015:

2015Settlement

2016Settlement

Natural GasThree-Way Collars (thousand MMBtu/d) 635 —

Average price per MMBtuCeiling sold price (call) $ 4.76 $ —Floor purchased price (put) $ 3.75 $ —Floor sold price (put) $ 2.75 $ —

Fixed-Price Contracts (thousand MMBtu/d) 7 28Average price per MMBtu $ 2.56 $ 3.22

Extendable Fixed-Price Contracts (thousand MMBtu/d) (1) 170 —Average price per MMBtu $ 4.17 $ —

OilThree-Way Collars (MBbls/d) — 28

Average price per barrelCeiling sold price (call) $ — $ 69.29Floor purchased price (put) $ — $ 61.43Floor sold price (put) $ — $ 46.43

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(1) The extendable fixed-price contracts have a contract term of January 2015 to December 2015 with an option for the counterparty to extend the contract term to December 2016 at the same price.

MMBtu—million British thermal unitsMMBtu/d—million British thermal units per dayMBbls/d—thousand barrels per day

A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

Marketing and Trading Derivative Activities The Company had financial derivative transactions with notional volumes of natural gas totaling 6 billion cubic feet at June 30, 2015 and December 31, 2014, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.

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Interest-Rate Derivatives Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month London Interbank Offered Rate (LIBOR). These swap instruments currently include a provision that requires both the termination of the swaps and cash settlement in full at the start of the reference period.

Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in the Company’s portfolio contain an other-than-insignificant financing element and, therefore, any settlements or collateralization related to these extended interest-rate derivatives are classified as cash flows from financing activities.

The Company had the following outstanding interest-rate swaps at June 30, 2015:

millions except percentages Reference Period Weighted-AverageNotional Principal Amount Start End Interest Rate$ 50 September 2016 September 2026 5.91%$ 1,850 September 2016 September 2046 6.06%

Effect of Derivative Instruments—Balance Sheet The following summarizes the fair value of the Company’s derivative instruments:

Gross Derivative Assets Gross Derivative Liabilitiesmillions June 30, December 31, June 30, December 31,Balance Sheet Classification 2015 2014 2015 2014Commodity derivatives

Other current assets $ 238 $ 421 $ (73) $ (118)Other assets 5 1 — —Accrued expenses 60 71 (89) (114)Other liabilities 34 — (40) (6)

337 493 (202) (238)Interest-rate derivatives

Other liabilities — — (1,110) (1,217)Total derivatives $ 337 $ 493 $ (1,312) $ (1,455)

Effect of Derivative Instruments—Statement of Income The following summarizes gains and losses related to derivative instruments:

millionsThree Months Ended


June 30,Classification of (Gain) Loss Recognized 2015 2014 2015 2014Commodity derivatives

Gathering, processing, and marketing sales (1) $ 1 $ 2 $ 1 $ 10(Gains) losses on derivatives, net 1 164 (52) 379

Interest-rate derivatives(Gains) losses on derivatives, net (312) 159 (107) 397

Total (gains) losses on derivatives, net $ (310) $ 325 $ (158) $ 786__________________________________________________________________

(1) Represents the effect of Marketing and Trading Derivative Activities.

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Credit-Risk Considerations The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure.

The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types. At June 30, 2015, $198 million of the Company’s $1.312 billion gross derivative liability balance, and at December 31, 2014, $289 million of the Company’s $1.455 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types.

The Company’s derivative instruments are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from major credit rating agencies declines to below investment grade. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $976 million (net of collateral) at June 30, 2015, and $97 million (net of collateral) at December 31, 2014. The increase is primarily a result of derivative counterparties no longer maintaining secured positions under the Company’s credit facilities and, therefore, the derivative instruments are now subject to credit-risk-related provisions. For information on the Company’s revolving credit facilities, see Note 8—Debt and Interest Expense—Anadarko Revolving Credit Facilities and Commercial Paper Program.

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Fair Value Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, discount factors and implied market volatility.

The following summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy:

millions June 30, 2015 Level 1 Level 2 Level 3 Netting (1) Collateral TotalAssets

Commodity derivativesFinancial institutions $ — $ 314 $ — $ (163) $ (3) $ 148Other counterparties — 23 — (4) — 19

Total derivative assets $ — $ 337 $ — $ (167) $ (3) $ 167Liabilities

Commodity derivativesFinancial institutions $ — $ (192) $ — $ 163 $ — $ (29)Other counterparties — (10) — 4 — (6)

Interest-rate derivatives — (1,110) — — 100 (1,010)Total derivative liabilities $ — $ (1,312) $ — $ 167 $ 100 $ (1,045)

December 31, 2014Assets

Commodity derivativesFinancial institutions $ — $ 471 $ — $ (187) $ (13) $ 271Other counterparties — 22 — (2) — 20

Total derivative assets $ — $ 493 $ — $ (189) $ (13) $ 291Liabilities

Commodity derivativesFinancial institutions $ — $ (234) $ — $ 187 $ — $ (47)Other counterparties — (4) — 2 — (2)

Interest-rate derivatives — (1,217) — — 23 (1,194)Total derivative liabilities $ — $ (1,455) $ — $ 189 $ 23 $ (1,243)

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(1) Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

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7. Tangible Equity Units

In June 2015, the Company issued 9.2 million 7.50% tangible equity units (TEUs) at a stated amount of $50.00 per TEU, raising net proceeds of $446 million. Each TEU is comprised of a prepaid equity purchase contract for common units of Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary, and a senior amortizing note. Subsequent to issuance, each TEU may be legally separated into the two components. The prepaid equity purchase contract is considered a freestanding financial instrument, indexed to WGP common units, and meets the conditions for equity classification.

Anadarko allocated the proceeds from the issuance of the TEUs to equity and debt based on the relative fair values of their respective components as follows:

millions, except price per TEUEquity

ComponentDebt

Component TotalPrice per TEU $ 39.05 $ 10.95 $ 50.00Gross proceeds 359 101 460Less issuance costs 11 3 14Net proceeds $ 348 $ 98 $ 446

The prepaid equity purchase contracts were recorded in noncontrolling interests, net of issuance costs, and the senior amortizing notes were recorded in short-term debt and long-term debt on the Company’s Consolidated Balance Sheet.

Equity Component Unless settled earlier at the holder’s option, each purchase contract has a mandatory settlement date of June 7, 2018. Anadarko has a right to elect to issue and deliver shares of Anadarko Petroleum Corporation common stock (APC shares) in lieu of delivering WGP common units at settlement. The Company will deliver WGP common units (or APC shares) on the settlement date at the settlement rate based upon the applicable market value of WGP common units (or APC shares) as follows:

Settlement Rate per Purchase ContractApplicable Market Value of WGP Common Units (1) WGP Common Units APC Shares (if elected) (1)

Exceeds $69.8422 (ThresholdAppreciation Price)

0.7159 units (MinimumSettlement Rate)

a number of shares equal to (a) the MinimumSettlement Rate, multiplied by the applicablemarket value of WGP common units, dividedby (b) 98% of the applicable market value ofAPC shares

Less than or equal to the ThresholdAppreciation Price, but greater thanor equal to $58.20 (Reference Price)

a number of units equal to$50.00, divided by theapplicable market value ofWGP common units

a number of shares equal to $50.00, dividedby 98% of the applicable market value ofAPC shares

Less than the Reference Price 0.8591 units (MaximumSettlement Rate)

a number of shares equal to (a) the MaximumSettlement Rate, multiplied by the applicablemarket value of WGP common units, dividedby (b) 98% of the applicable market value ofAPC shares

__________________________________________________________________

(1) The applicable market value is the average of the daily volume-weighted average prices of WGP common units (or APC shares) for the 20 consecutive trading days beginning on, and including, the 23rd scheduled trading day immediately preceding June 7, 2018.

The WGP common units underlying the purchase contract are currently issued and outstanding, and are owned by a wholly owned subsidiary of Anadarko. In the event Anadarko elects to settle in APC shares, the number of such shares issued and delivered upon settlement of each purchase contract is subject to adjustment and cannot exceed four shares under any circumstance (APC share cap). The above fixed settlement rates for WGP common units and the APC share cap are subject to adjustment upon the occurrence of certain specified dilutive events.

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7. Tangible Equity Units (Continued)

Debt Component Each senior amortizing note has an initial principal amount of $10.95 and bears interest at 1.50% per year. Beginning September 7, 2015, Anadarko will pay equal quarterly cash installments of $0.9375 per amortizing note (except for the September 7, 2015 installment payment, which will be $0.9063 per amortizing note). The payments will constitute a payment of interest and partial repayment of principal, with the aggregate per-year payments of principal and interest equating to a 7.50% cash payment with respect to each TEU. The senior amortizing notes have a final installment payment date of June 7, 2018, and are senior unsecured obligations of the Company.

8. Debt and Interest Expense

Debt The Company’s outstanding debt, excluding the capital lease obligation, is senior unsecured. The following summarizes the Company’s outstanding debt:

millionsJune 30,

2015December 31,

2014Total debt at face value $ 17,640 $ 16,687Net unamortized discounts and premiums (1) (1,603) (1,616)Total borrowings 16,037 15,071Capital lease obligation 21 21Less short-term debt 33 —Total long-term debt (2) $ 16,025 $ 15,092

__________________________________________________________________

(1) Unamortized discounts and premiums are amortized over the term of the related debt.(2) Includes WES debt of $2.7 billion at June 30, 2015, and $2.4 billion at December 31, 2014.

Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $796 million at the next put date in October 2015. Anadarko’s Zero Coupons are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt.

Fair Value The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the variable interest rates are reflective of market rates. The estimated fair value of the Company’s total borrowings was $17.9 billion at June 30, 2015, and $17.4 billion at December 31, 2014.

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8. Debt and Interest Expense (Continued)

Debt Activity The following summarizes the Company’s debt activity during the six months ended June 30, 2015:

Carrying millions Value DescriptionBalance at December 31, 2014 $ 15,071

Issuances 494 WES 3.950% Senior Notes due 2025101 Tangible Equity Units - senior amortizing notes

Borrowings 1,500 $5.0 billion revolving credit facility1,800 364-Day Facility

280 WES revolving credit facility592 Commercial paper notes, net (1)

Repayments (1,500) $5.0 billion revolving credit facility(1,800) 364-Day Facility

(520) WES revolving credit facilityOther, net 19 Amortization of debt discounts and premiums

Balance at June 30, 2015 $ 16,037__________________________________________________________________

(1) Includes repayments of $37 million related to commercial paper notes with maturities greater than 90 days.

Anadarko Revolving Credit Facilities and Commercial Paper Program In January 2015, upon satisfaction of certain conditions, including the settlement payment related to the Tronox Adversary Proceeding, the Company’s $5.0 billion senior secured revolving credit facility was replaced by a $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility), which is expandable to $4.0 billion, and a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility). For additional information, see Note 12—Contingencies—Tronox Litigation.

Borrowings under the Five-Year and 364-Day Facilities generally bear interest under one of two rate options, at Anadarko’s election, using either LIBOR (or Euro Interbank Offered Rate in the case of borrowings under the Five-Year Facility denominated in Euro) or an alternate base rate, in each case plus an applicable margin ranging from 0.00% to 1.65% for the Five-Year Facility and 0.00% to 1.675% for the 364-Day Facility. The applicable margin will vary depending on Anadarko’s credit ratings.

The Five-Year and 364-Day Facilities contain certain customary affirmative and negative covenants, including a financial covenant requiring maintenance of a consolidated indebtedness to total capitalization ratio of no greater than 65% and limitations on certain secured indebtedness, sale-and-leaseback transactions, and mergers and other fundamental changes. At June 30, 2015, the Company had no outstanding borrowings under the Five-Year and 364-Day Facilities and was in compliance with all covenants contained therein.

During the first quarter of 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Company’s Five-Year Facility. The maturities of the commercial paper notes vary, but may not exceed 397 days. The commercial paper notes are sold under customary terms in the commercial paper market and are issued either at a discounted price to their principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted price or interest amounts are dependent on market conditions and the ratings assigned to the commercial paper program by credit rating agencies at the time of issuance of the commercial paper notes. At June 30, 2015, the Company had $592 million of commercial paper notes outstanding at a weighted-average interest rate of 0.51%. Anadarko classified the outstanding commercial paper notes as long-term debt on the Company’s Consolidated Balance Sheet, as the Company currently intends to refinance these obligations at maturity with additional commercial paper notes supported by Anadarko’s Five-Year Facility.

WES Borrowings During the second quarter of 2015, WES completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025. At June 30, 2015, WES was in compliance with all covenants contained in its five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which is expandable to $1.5 billion. At June 30, 2015, WES had outstanding borrowings under its RCF of $270 million at an interest rate of 1.49%, had outstanding letters of credit of $13 million, and had available borrowing capacity of $917 million.

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8. Debt and Interest Expense (Continued)

Interest Expense The following summarizes interest expense:

Three Months Ended


June 30,millions 2015 2014 2015 2014Debt and other $ 244 $ 233 $ 498 $ 473Capitalized interest (43) (47) (81) (104)Total interest expense $ 201 $ 186 $ 417 $ 369

9. Stockholders’ Equity

The Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities and TEUs as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and TEUs, if the inclusion of these items is dilutive.

The following provides a reconciliation between basic and diluted earnings per share attributable to common stockholders:

Three Months Ended


June 30,millions except per-share amounts 2015 2014 2015 2014Net income (loss)

Net income (loss) attributable to common stockholders $ 61 $ 227 $ (3,207) $ (2,442)Less distributions on participating securities 1 1 2 1Basic $ 60 $ 226 $ (3,209) $ (2,443)Diluted $ 60 $ 226 $ (3,209) $ (2,443)

SharesAverage number of common shares outstanding—basic 508 505 507 505Dilutive effect of stock options 1 2 — —Average number of common shares outstanding—diluted 509 507 507 505Excluded due to anti-dilutive effect 6 4 11 11

Net income (loss) per common shareBasic $ 0.12 $ 0.45 $ (6.32) $ (4.84)Diluted $ 0.12 $ 0.45 $ (6.32) $ (4.84)

10. Accumulated Other Comprehensive Income (Loss)

The following summarizes the after-tax changes in the balances of accumulated other comprehensive income (loss):

millions

Interest-rate Derivatives Previously

Subject to Hedge Accounting

Pension and Other

PostretirementPlans Total

Balance at December 31, 2014 $ (48) $ (469) $ (517)Reclassifications to Consolidated Statement of Income 3 18 21

Balance at June 30, 2015 $ (45) $ (451) $ (496)

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11. Noncontrolling Interests

WGP, a publicly traded consolidated subsidiary, is a limited partnership that owns interests in WES. During the three months ended June 30, 2015, Anadarko sold 2.3 million WGP common units to the public, raising net proceeds of $130 million. At June 30, 2015, Anadarko’s ownership interest in WGP consisted of an 87.3% limited partner interest and the entire non-economic general partner interest. The remaining 12.7% limited partner interest in WGP was owned by the public. In June 2015, Anadarko issued 9.2 million TEUs, which include an equity component that may be settled in WGP common units. For additional disclosure of the TEU effect on noncontrolling interests, see Note 7—Tangible Equity Units.

WES, a publicly traded consolidated subsidiary, is a limited partnership that acquires, owns, develops, and operates midstream assets. During the six months ended June 30, 2015, WES issued 874 thousand common units to the public under its continuous offering program, raising net proceeds of $57 million. In 2014, WES issued 11 million Class C units to Anadarko to partially fund the acquisition of DBM. These Class C units receive distributions in the form of additional Class C units until conversion into common units at the end of 2017 unless WES elects to convert the units earlier or Anadarko extends the conversion date. During the six months ended June 30, 2015, WES distributed 164 thousand Class C units to Anadarko. At June 30, 2015, WGP’s ownership interest in WES consisted of a 34.7% limited partner interest, the entire 1.8% general partner interest, and all of the WES incentive distribution rights. At June 30, 2015, Anadarko also owned an 8.3% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 55.2% limited partner interest in WES was owned by the public.

12. Contingencies

Litigation The following is a discussion of any material developments in previously reported contingencies and any other material matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Tronox Litigation On April 3, 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries entered into a settlement agreement to resolve all claims asserted by Tronox Incorporated (Tronox) and certain of its affiliates, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding), for $5.15 billion. In addition, the Company agreed to pay interest on that amount from April 3, 2014, through the payment of the settlement. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective. For additional disclosure of the Tronox Adversary Proceeding, see Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Anadarko recognized Tronox-related contingent losses of $850 million in the fourth quarter of 2013 and $4.3 billion in the first quarter of 2014. In addition, Anadarko recognized settlement-related interest expense, included in Tronox-related contingent loss in the Company’s Consolidated Statement of Income, of $60 million during the year ended December 31, 2014, and $5 million during the first quarter of 2015. For information on the tax effects of the settlement agreement, see Note 13—Income Taxes.

Deepwater Horizon Events In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig, resulting in an oil spill. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% nonoperated interest. In October 2011, the Company and BP entered into a settlement agreement relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims and damages arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and any claims arising under the Operating Agreement with BP. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against penalties and fines, punitive damages, shareholder derivative or securities laws claims, or certain other claims. The Company has not recorded a liability for any costs that are subject to indemnification by BP. For additional disclosure of the Deepwater Horizon events, the Company’s Settlement Agreement with BP, environmental claims under OPA, NRD claims, potential penalties and fines, and civil litigation, see Note 17—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

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12. Contingencies (Continued)

Penalties and Fines In December 2010, the U.S. Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the U.S. District Court for the Eastern District of Louisiana in New Orleans, Louisiana (Louisiana District Court) against several parties, including the Company, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. In February 2012, the Louisiana District Court entered a declaratory judgment that, as a partial owner of the Macondo well, Anadarko is liable for civil penalties under Section 311 of the CWA. The declaratory judgment was affirmed in June 2014 by the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit). In March 2015, Anadarko filed a petition for a writ of certiorari with the U.S. Supreme Court appealing the Fifth Circuit’s decision, which was denied in June 2015. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. The assessment of a civil penalty against Anadarko will be determined by the Louisiana District Court upon its ruling in the penalty phase of trial discussed below under Civil Litigation Damage Claims.

Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. The Louisiana District Court’s declaratory judgment in February 2012 satisfies the requirement that a liability arising from the future assessment of a civil penalty against Anadarko is probable. In an effort to resolve this matter, the Company made a settlement offer to the DOJ in July 2014 of $90 million and recorded a contingent liability for this amount at June 30, 2014. The Company subsequently engaged in further discussions regarding settlement, but the parties have not been able to reach agreement on either the amount of, or the terms and conditions governing, a settlement. The Company’s settlement offer of $90 million remains outstanding and the Company remains open to resolving the matter through settlement discussions. The Company believes that $90 million under a settlement scenario is a better estimate of loss at this time than any other amount. Based on the above accounting guidance, the Company’s contingent liability for CWA penalties and fines remains $90 million at June 30, 2015. However, the Company may ultimately incur a liability related to CWA penalties in excess of the current accrued liability.

The actual amount of a CWA penalty is subject to uncertainty, including whether the Company will be able to reach a settlement with the DOJ or will await the Louisiana District Court’s opinion in the penalty phase trial. The CWA sets forth subjective criteria to be considered by the court in assessing the magnitude of any CWA penalty: economic benefit to the violator; degree of culpability; seriousness of the violation; the nature, extent, and degree of success of any efforts to minimize or mitigate the effects of the discharge; prior history of violations; other penalties for the same incident; economic impact of the penalty on the violator; and other matters as justice may require. For the Phase I and II trials (defined in Civil Litigation Damage Claims below) and again for the penalty phase trial in January 2015, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault could be presented. In addition, in its Phase I Findings of Fact and Conclusions of Law (Phase I Findings and Conclusions), the Louisiana District Court did not allocate any fault to Anadarko. Given the subjective nature of the CWA criteria used to determine penalty assessments and the Louisiana District Court’s prior rulings related to culpability and allocation of fault, the Company currently cannot reasonably estimate the amount of any such penalty to be assessed or determine a reasonable range of potential loss if the matter is resolved by the Louisiana District Court following trial. Furthermore, BP’s July 2015 announcement of a settlement agreement in principle with the DOJ and the five Gulf states (Texas, Louisiana, Mississippi, Alabama, and Florida) regarding essentially all of the outstanding claims against BP related to the Deepwater Horizon event, including $5.5 billion to resolve CWA penalties, does not affect the Company’s current conclusion concerning its ability to estimate potential fines and penalties. The Company lacks insight into that settlement, which has yet to be finalized, retains legal counsel separate from BP, and was not involved in any manner with respect to that settlement. In addition, the consent decree covering the terms and conditions of BP’s announced settlement has yet to be disclosed.

Although the Company currently cannot reasonably estimate the amount of any such penalty to be assessed or determine a reasonable range of potential loss, the Company believes the following factors should limit the magnitude of any CWA penalties assessed:

• the Company’s lack of direct operational involvement in the event as a non-operator,

• the Louisiana District Court’s rulings excluding any evidence of Anadarko’s alleged culpability or fault, and

• the Phase I Findings and Conclusions that did not allocate any fault to Anadarko.

In addition, the Company is not aware that any court has ever assessed a substantial CWA penalty against a party who has been found by a court to bear no fault for a spill.

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Events or factors that could assist the Company in estimating the amount of settlement or potential civil penalty or a range of potential loss related to such penalty include a ruling by the Louisiana District Court or substantive settlement negotiations between the Company and the DOJ.

As discussed below, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Certain state and local governments appealed, or provided indication of a likely appeal of, the Louisiana District Court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. It is unclear whether these appeals will be dismissed as part of BP’s announced settlement. If any such appeal proceeds and is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.

Civil Litigation Damage Claims Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court.

The first phase of the trial in the MDL (Phase I) commenced in February 2013. The issues tried in Phase I included the cause of the blowout and all related events leading up to April 22, 2010, the date the Deepwater Horizon sank, as well as allocation of fault. In September 2014, the Louisiana District Court issued its Phase I Findings and Conclusions. The Louisiana District Court found that BP and BP America Production Company (BPAP), Transocean Ltd. (Transocean), and Halliburton Energy Services, Inc. (Halliburton), but not Anadarko, are each liable under general maritime law for the blowout, explosion, and oil spill. The court determined that BP’s and BPAP’s conduct was reckless and that both Transocean’s and Halliburton’s conduct was negligent. The Louisiana District Court apportioned 67% of the fault to BP and BPAP, 30% to Transocean, and 3% to Halliburton. No fault was allocated to Anadarko. The plaintiffs and BP have appealed the Phase I Findings and Conclusions.

The second phase of trial (Phase II) began in September 2013. The issues tried in Phase II included spill-source control and quantification of the spill for the period from April 20, 2010, until the well was capped. In January 2015, the Louisiana District Court issued its Phase II Findings of Fact and Conclusions of Law (Phase II Findings and Conclusions). The Louisiana District Court found that, for purposes of calculating the maximum possible civil penalty under the CWA, 3.19 million barrels of oil were discharged into the Gulf of Mexico. The United States has appealed the Phase II Findings and Conclusions.

The penalty phase of the trial began in January 2015. In March 2014, the Louisiana District Court ruled that no evidence of Anadarko’s alleged culpability or fault could be presented during the penalty phase trial. The parties rested their case in February 2015, post-trial briefing concluded in April 2015, and the matter is pending before the Louisiana District Court. The trial included Anadarko, BP, and the United States, and will assess findings and penalties under the CWA.

Remaining Liability Outlook In addition to the assessment of civil penalties under the CWA discussed above, it is possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties and certain other claims not covered by the indemnification provisions of the Settlement Agreement.

Although the Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and certain other potential liabilities, the Company may be required to recognize a liability for these amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c.

The Company will continue to monitor the MDL and other legal proceedings discussed above, as well as federal investigations related to the Deepwater Horizon events. The Company cannot predict the nature of additional evidence that may be discovered during the course of legal proceedings or the timing of completion of any legal proceedings.

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Other Litigation In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. In August 2013, following a determination by an administrative court in a related matter that the amount of tax in dispute was not calculated properly, the Company filed a petition requesting the withdrawal of a portion of the judicial deposit to the extent it exceeds the amount of tax currently in dispute, and any interest on such amount. In April 2015, the Company’s petition was denied. For additional disclosure on this matter, see Note 17—Contingencies—Other Litigation in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

The Company believes that it will more likely than not prevail in Brazilian courts. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation at June 30, 2015.

13. Income Taxes

The following summarizes income tax expense (benefit) and effective tax rates:

Three Months Ended


June 30,millions except percentages 2015 2014 2015 2014Income tax expense (benefit) $ 77 $ 428 $ (1,315) $ 1,092Income (loss) before income taxes 185 694 (4,443) (1,268)Effective tax rate 42% 62% 30% (86)%

The increase from the 35% U.S. federal statutory rate for the three months ended June 30, 2015 and 2014, was primarily attributable to the tax impact from foreign operations and Algerian exceptional profits taxes. The increase from the 35% U.S. federal statutory rate for the three months ended June 30, 2014, was also attributable to net changes in uncertain tax positions and the non-deductible contingent CWA-penalty accrual.

The Company reported a loss before income taxes for the six months ended June 30, 2015 and 2014. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 2015, was primarily attributable to Algerian exceptional profits taxes and the tax impact from foreign operations. The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 2014, was primarily attributable to net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding, the tax impact from foreign operations, Algerian exceptional profits taxes, and the non-deductible contingent CWA-penalty accrual.

At June 30, 2015, the Company had recorded a $577 million tax benefit related to the Tronox settlement. This benefit was net of a $1.3 billion uncertain tax position due to the uncertainty related to the deductibility of the settlement payment. The Company is a participant in the U.S. Internal Revenue Service’s (IRS) Compliance Assurance Process and has regular discussions with the IRS concerning the Company’s tax positions. Depending on the outcome of such discussions, it is reasonably possible that the amount of the uncertain tax position related to the settlement could change, perhaps materially. See Note 12—Contingencies—Tronox Litigation.

At June 30, 2015, the Company’s Consolidated Balance Sheet included $675 million of income taxes receivable presented in accounts receivable—others and $289 million of accrued income taxes presented in accrued expenses.

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14. Supplemental Cash Flow Information

The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities:

Six Months Ended

June 30,millions 2015 2014Cash paid (received)

Interest, net of amounts capitalized (1) $ 1,621 $ 342Income taxes, net of refunds 6 655

Non-cash investing activitiesFair value of properties and equipment from non-cash transactions $ 126 $ 5Asset retirement cost additions 90 122Accruals of property, plant, and equipment 901 1,344Net liabilities assumed (divested) in acquisitions and divestitures (29) (32)

Non-cash investing and financing activitiesFloating production, storage, and offloading vessel construction period obligation $ 43 $ 53

__________________________________________________________________

(1) Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.

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15. Segment Information

Anadarko’s business segments are separately managed due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production segment explores for and produces natural gas, oil, condensate, and NGLs, and plans for the development and operation of the Company’s LNG project in Mozambique. The midstream segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The midstream reporting segment consists of two operating segments, WES and other midstream, which are aggregated into one reporting segment due to similar financial and operating characteristics. The marketing segment sells much of Anadarko’s oil, natural-gas, and NGLs production, as well as third-party purchased volumes.

To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; interest expense; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; and certain items not related to the Company’s normal operations, less net income attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included Deepwater Horizon settlement and related costs, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX excludes exploration expense as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.

Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders. Adjusted EBITDAX as defined by Anadarko may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:

Three Months Ended


June 30,millions 2015 2014 2015 2014Income (loss) before income taxes $ 185 $ 694 $ (4,443) $ (1,268)Exploration expense 103 502 1,186 801DD&A 1,214 1,048 2,470 2,172Impairments 30 117 2,813 120Interest expense 201 186 417 369Total (gains) losses on derivatives, net, less net cash from

settlement of commodity derivatives (229) 237 14 600Deepwater Horizon settlement and related costs — 93 4 93Tronox-related contingent loss — 19 5 4,319Certain other nonoperating items — — 22 —Less net income attributable to noncontrolling interests 47 39 79 82Consolidated Adjusted EBITDAX $ 1,457 $ 2,857 $ 2,409 $ 7,124

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15. Segment Information (Continued)

Information presented below as “Other and Intersegment Eliminations” includes corporate costs, results from hard-minerals royalties, and net cash from settlement of commodity derivatives. The following summarizes selected financial information for Anadarko’s reporting segments:

millions

Oil and GasExploration

& Production Midstream Marketing

Other andIntersegmentEliminations Total

Three Months Ended June 30, 2015Sales revenues $ 1,356 $ 191 $ 1,090 $ — $ 2,637Intersegment revenues 885 303 (954) (234) —Gains (losses) on divestitures and other, net (95) 3 — 91 (1)

Total revenues and other 2,146 497 136 (143) 2,636Operating costs and expenses (1) 832 234 192 (59) 1,199Net cash from settlement of commodity

derivatives — — — (82) (82)Other (income) expense, net (2) — — — 15 15Net income attributable to noncontrolling interests — 47 — — 47

Total expenses and other 832 281 192 (126) 1,179Total (gains) losses on derivatives, net included in

marketing revenue, less net cash fromsettlement — — — — —

Adjusted EBITDAX $ 1,314 $ 216 $ (56) $ (17) $ 1,457

Three Months Ended June 30, 2014Sales revenues $ 2,223 $ 119 $ 2,043 $ — $ 4,385Intersegment revenues 1,790 326 (1,906) (210) —Gains (losses) on divestitures and other, net 10 (1) — 45 54

Total revenues and other 4,023 444 137 (165) 4,439Operating costs and expenses (1) 1,026 251 186 7 1,470Net cash from settlement of commodity

derivatives — — — 88 88Other (income) expense, net (2) — — — (13) (13)Net income attributable to noncontrolling interests — 39 — — 39

Total expenses and other 1,026 290 186 82 1,584Total (gains) losses on derivatives, net included in

marketing revenue, less net cash fromsettlement — — 2 — 2

Adjusted EBITDAX $ 2,997 $ 154 $ (47) $ (247) $ 2,857 __________________________________________________________________

(1) Operating costs and expenses excludes exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX.

(2) Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

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15. Segment Information (Continued)

millions

Oil and GasExploration

& Production Midstream Marketing

Other andIntersegmentEliminations Total

Six Months Ended June 30, 2015Sales revenues $ 2,426 $ 365 $ 2,431 $ — $ 5,222Intersegment revenues 2,002 605 (2,145) (462) —Gains (losses) on divestitures and other, net (433) 3 — 165 (265)

Total revenues and other 3,995 973 286 (297) 4,957Operating costs and expenses (1) 1,834 474 390 (96) 2,602Net cash from settlement of commodity

derivatives — — — (172) (172)Other (income) expense, net (2) — — — 40 40Net income attributable to noncontrolling interests — 79 — — 79

Total expenses and other 1,834 553 390 (228) 2,549Total (gains) losses on derivatives, net included in


Adjusted EBITDAX $ 2,161 $ 420 $ (103) $ (69) $ 2,409

Six Months Ended June 30, 2014Sales revenues $ 4,612 $ 239 $ 3,872 $ — $ 8,723Intersegment revenues 3,343 646 (3,595) (394) —Gains (losses) on divestitures and other, net 1,470 (3) — 93 1,560

Total revenues and other 9,425 882 277 (301) 10,283Operating costs and expenses (1) 2,038 483 367 25 2,913Net cash from settlement of commodity

derivatives — — — 180 180Other (income) expense, net (2) — — — (12) (12)Net income attributable to noncontrolling interests — 82 — — 82

Total expenses and other 2,038 565 367 193 3,163Total (gains) losses on derivatives, net included in


Adjusted EBITDAX $ 7,387 $ 317 $ (86) $ (494) $ 7,124 __________________________________________________________________

(1) Operating costs and expenses excludes exploration expense, DD&A, impairments, and Deepwater Horizon settlement and related costs since these expenses are excluded from Adjusted EBITDAX.

(2) Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

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16. Pension Plans and Other Postretirement Benefits

The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory. The following summarizes the Company’s pension and other postretirement benefit cost:

Pension Benefits Other Benefitsmillions 2015 2014 2015 2014Three Months Ended June 30Service cost $ 29 $ 24 $ 2 $ 2Interest cost 26 25 4 3Expected return on plan assets (28) (26) — —Amortization of net actuarial loss (gain) 13 8 — (1)Amortization of net prior service cost (credit) — — 1 —Net periodic benefit cost $ 40 $ 31 $ 7 $ 4

Six Months Ended June 30Service cost $ 59 $ 49 $ 5 $ 4Interest cost 51 50 8 7Expected return on plan assets (55) (53) — —Amortization of net actuarial loss (gain) 26 17 — (3)Amortization of net prior service cost (credit) — — 1 —Net periodic benefit cost $ 81 $ 63 $ 14 $ 8

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company has made in this report, and may from time to time make in other public filings, press releases, and management discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include, among other things, information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by, or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” “would,” “will,” “potential,” “continue,” “forecast,” “future,” “likely,” “outlook,” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will be realized. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:

• the Company’s assumptions about energy markets• production and sales volume levels• reserves levels• operating results• competitive conditions• technology• availability of capital resources, levels of capital expenditures, and other contractual obligations• supply and demand for, the price of, and the commercialization and transporting of natural gas, oil, natural gas

liquids (NGLs), and other products or services• volatility in the commodity-futures market• weather• inflation• availability of goods and services, including unexpected changes in costs• drilling risks• processing volumes and pipeline throughput• general economic conditions nationally, internationally, or in the jurisdictions in which the Company or its

subsidiaries are, or in the future may be, doing business• the Company’s inability to timely obtain or maintain permits or other governmental approvals, including those

necessary for drilling and/or development projects• legislative or regulatory changes, including changes relating to hydraulic fracturing; retroactive royalty or

production tax regimes; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation; environmental risks; and liability under federal, state, foreign, and local environmental laws and regulations

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• the ability of BP Exploration & Production Inc. (BP) to meet its indemnification obligations to the Company for Deepwater Horizon events, including, among other things, damage claims arising under the Oil Pollution Act of 1990, claims for natural resource damages and associated damage-assessment costs, and any claims arising under the Operating Agreement for the Macondo well, as well as the ability of BP Corporation North America Inc. and BP p.l.c. to satisfy their guarantees of such indemnification obligations

• the impact of remaining claims related to the Deepwater Horizon events, including, but not limited to, fines, penalties, and punitive damages against the Company, for which it is not indemnified by BP

• civil or political unrest or acts of terrorism in a region or country• the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating

partners, and other parties• volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity, and interest-

rate risk• the Company’s ability to successfully monetize select assets, repay its debt, and the impact of changes in the Company’s

credit ratings• disruptions in international oil, NGLs, and condensate cargo shipping activities• physical, digital, internal, and external security breaches• supply and demand, technological, political, governmental, and commercial conditions associated with long-term

development and production projects in domestic and international locations• other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of

Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Part I, Item 1; the information set forth in Risk Factors under Part II, Item 1A; the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014; and the information set forth in the Risk Factors under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

OVERVIEW

Anadarko is among the world’s largest independent exploration and production companies. Anadarko is engaged in the exploration, development, production, and marketing of natural gas, oil, condensate, NGLs, and the anticipated production of liquefied natural gas. The Company also engages in the gathering, processing, treating, and transporting of natural gas, oil, and NGLs. The Company has production and exploration activities worldwide, including activities in the United States, Mozambique, Algeria, Ghana, Brazil, Colombia, Côte d’Ivoire, Kenya, New Zealand, and other countries.

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Significant operating and financial activities for the second quarter of 2015 include the following:

Overall

• Anadarko’s second-quarter sales volumes averaged 846 thousand barrels of oil equivalent per day (MBOE/d), which was essentially flat compared to the second quarter of 2014.

• Oil and NGLs (liquids) sales volumes increased by 43 thousand barrels per day (MBbls/d), representing a 10% increase from the second quarter of 2014. This increase included a 15 MBbls/d decrease in sales volumes related to the divestitures of certain enhanced oil recovery (EOR) assets in the Rocky Mountains Region (Rockies) and the Company’s Chinese subsidiary.

• The Company’s overall sales product mix increased to 53% liquids in the second quarter of 2015 compared to 49% in the second quarter of 2014.

U.S. Onshore

• U.S. onshore second-quarter liquids sales volumes increased by 38 MBbls/d, representing a 15% increase from the second quarter of 2014, primarily due to higher sales volumes from the Wattenberg field, the Eagleford shale, and the Delaware basin, partially offset by lower sales volumes due to the sale of certain EOR assets in April 2015.

• U.S. onshore second-quarter natural-gas sales volumes decreased by 35 MBOE/d, representing an 8% decrease from the second quarter of 2014, reflecting third-party infrastructure downtime and curtailments, as well as the Company’s storage of natural-gas volumes during the second quarter of 2015.

• The sale of certain EOR assets in the Rockies, with an original sales price of $703 million, closed in April 2015 for net proceeds of $686 million after closing adjustments.

• In early July, the Company entered into an agreement to sell certain U.S. onshore oil and gas exploration and production properties and related midstream assets in East Texas for $440 million, subject to closing adjustments, recognizing a loss of $97 million in the second quarter of 2015.

Gulf of Mexico

• Gulf of Mexico second-quarter sales volumes averaged 83 MBOE/d, representing a 9% increase from the second quarter of 2014, primarily due to the commencement of oil production from the Lucius development in January 2015, partially offset by natural-gas production declines at Independence Hub.

• The Company completed operations on the Thorvald exploration well (50% working interest), encountering approximately 80 net feet of oil pay. The well tested multiple sub-salt reservoirs in a three-way closure.

International

• International second-quarter sales volumes averaged 84 MBbls/d, representing a 12% decrease from the second quarter of 2014, primarily due to the timing of cargo liftings in Algeria and the sale of the Company’s Chinese subsidiary in August 2014, partially offset by an increase in Ghana due to the timing of cargo liftings.

• The Kronos-1 prospect in deepwater Colombia has encountered 130 to 230 net feet of natural-gas pay in the upper objective. The well is still drilling to test a deeper objective.

Financial

• Anadarko’s net income attributable to common stockholders for the second quarter of 2015 totaled $61 million.

• The Company generated $1.2 billion of cash flow from operations and ended the quarter with $2.2 billion of cash on hand.

• Western Gas Partners, LP (WES), a publicly traded consolidated subsidiary, completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025.

• Anadarko issued 9.2 million 7.50% tangible equity units (TEUs) at a stated amount of $50.00 per unit, raising net proceeds of $446 million.

• Anadarko completed a public secondary offering of 2.3 million common units in Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary that owns partnership interests in WES, raising net proceeds of $130 million.

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The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the three months ended June 30, 2015,” refer to the comparison of the three months ended June 30, 2015, to the three months ended June 30, 2014, and any increases or decreases “for the six months ended June 30, 2015,” refer to the comparison of the six months ended June 30, 2015, to the six months ended June 30, 2014. The primary factors that affect the Company’s results of operations include commodity prices for natural gas, oil, and NGLs; sales volumes; the Company’s ability to discover additional oil and natural-gas reserves; the cost of finding such reserves; and operating costs.

RESULTS OF OPERATIONS

Three Months Ended


June 30,millions except per-share amounts 2015 2014 2015 2014Financial ResultsRevenues and other $ 2,636 $ 4,439 $ 4,957 $ 10,283Costs and expenses 2,546 3,230 9,075 6,099Other (income) expense (95) 515 325 5,452Income tax expense (benefit) 77 428 (1,315) 1,092Net income (loss) attributable to common stockholders $ 61 $ 227 $ (3,207) $ (2,442)Net income (loss) per common share attributable to common

stockholders—diluted $ 0.12 $ 0.45 $ (6.32) $ (4.84)Average number of common shares outstanding—diluted 509 507 507 505

Operating ResultsAdjusted EBITDAX (1) $ 1,457 $ 2,857 $ 2,409 $ 7,124Sales volumes (MMBOE) 77 77 161 151

________________________________________________________________________________________________________

MMBOE—million barrels of oil equivalent(1) See Operating Results—Segment Analysis—Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a U.S.

Generally Accepted Accounting Principles (GAAP) measure, and for a reconciliation of Adjusted EBITDAX to income (loss) before income taxes, which is presented in accordance with GAAP.

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FINANCIAL RESULTS

Sales Revenues and Volumes


millions except percentagesNatural

GasOil and

Condensate NGLs Total2014 sales revenues $ 991 $ 2,705 $ 411 $ 4,107

Changes associated with sales volumes (101) 250 54 203Changes associated with prices (403) (1,339) (236) (1,978)

2015 sales revenues $ 487 $ 1,616 $ 229 $ 2,332Increase (decrease) vs. 2014 (51)% (40)% (44)% (43)%


millions except percentagesNatural

GasOil and

Condensate NGLs Total2014 sales revenues $ 2,208 $ 5,129 $ 797 $ 8,134

Changes associated with sales volumes (94) 824 218 948Changes associated with prices (986) (2,918) (554) (4,458)

2015 sales revenues $ 1,128 $ 3,035 $ 461 $ 4,624Increase (decrease) vs. 2014 (49)% (41)% (42)% (43)%

Anadarko’s sales revenues decreased for the three and six months ended June 30, 2015, due to lower average commodity prices and lower natural-gas sales volumes, partially offset by higher sales volumes for oil and NGLs.

Three Months Ended


June 30,

Sales Volumes 2015Inc/(Dec)vs. 2014 2014 2015

Inc/(Dec)vs. 2014 2014

Barrels of Oil Equivalent (MMBOE except percentages)United States 69 1% 68 144 7% 134International 8 (12) 9 17 1 17Total barrels of oil equivalent 77 — 77 161 7 151

Barrels of Oil Equivalent per Day (MBOE/d except percentages)United States 762 1% 752 796 7% 741International 84 (12) 96 94 1 93Total barrels of oil equivalent per day 846 — 848 890 7 834

Sales volumes represent actual production volumes adjusted for changes in commodity inventories and natural-gas production volumes provided to satisfy a commitment established in conjunction with a development plan. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q and Other (Income) Expense—(Gains) Losses on Derivatives, net.

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Natural-Gas Sales Volumes, Average Prices, and Revenues

Three Months Ended


June 30,

2015Inc/(Dec)vs. 2014 2014 2015

Inc/(Dec)vs. 2014 2014

United StatesSales volumes—Bcf 215 (10)% 238 461 (4)% 481

MMcf/d 2,354 (10) 2,620 2,545 (4) 2,658Price per Mcf $ 2.28 (45) $ 4.16 $ 2.45 (47) $ 4.59Natural-gas sales revenues (millions) $ 487 (51) $ 991 $ 1,128 (49) $ 2,208

_______________________________________________________________________________

Bcf—billion cubic feetMMcf/d—million cubic feet per dayMcf—thousand cubic feet

The Company’s natural-gas sales volumes decreased by 266 MMcf/d for the three months ended June 30, 2015, and 113 MMcf/d for the six months ended June 30, 2015.

• Sales volumes in the Southern and Appalachia Region decreased by 213 MMcf/d for the three months ended June 30, 2015, and 76 MMcf/d for the six months ended June 30, 2015, primarily due to third-party infrastructure downtime and curtailments, as well as the Company’s storage of natural-gas volumes during the second quarter of 2015. These decreases were partially offset by higher sales volumes as a result of continued horizontal drilling in the Eagleford shale.

• Sales volumes in the Gulf of Mexico decreased by 62 MMcf/d for the three months ended June 30, 2015, and 58 MMcf/d for the six months ended June 30, 2015, primarily due to natural production declines at Independence Hub.

• Sales volumes in the Rockies increased by 9 MMcf/d for the three months ended June 30, 2015, and 21 MMcf/d for the six months ended June 30, 2015, due to higher sales volumes in the Wattenberg field as a result of continued horizontal drilling, partially offset by natural production declines at Greater Natural Buttes and the Powder River basin.

The average natural-gas price Anadarko received decreased for the three and six months ended June 30, 2015, primarily due to strong year-over-year production growth in the northeast United States and slightly lower weather-driven residential and commercial demand.

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Oil and Condensate Sales Volumes, Average Prices, and Revenues

Three Months Ended


June 30,

2015Inc/(Dec)vs. 2014 2014 2015

Inc/(Dec)vs. 2014 2014

United StatesSales volumes—MMBbls 21 22 % 18 43 26 % 34

MBbls/d 240 22 196 238 26 189Price per barrel $ 54.14 (45) $ 98.69 $ 49.23 (49) $ 96.86InternationalSales volumes—MMBbls 8 (17)% 9 16 (4)% 17

MBbls/d 78 (17) 95 88 (4) 92Price per barrel $ 60.81 (44) $ 109.00 $ 57.12 (47) $ 108.71TotalSales volumes—MMBbls 29 9 % 27 59 16 % 51

MBbls/d 318 9 291 326 16 281Price per barrel $ 55.78 (45) $ 102.04 $ 51.37 (49) $ 100.76Oil and condensate sales revenues (millions) $ 1,616 (40) $ 2,705 $ 3,035 (41) $ 5,129

_______________________________________________________________________________

MMBbls—million barrels

Anadarko’s oil and condensate sales volumes increased by 27 MBbls/d for the three months ended June 30, 2015, and 45 MBbls/d for the six months ended June 30, 2015.

• Sales volumes in the Rockies increased by 13 MBbls/d for the three months ended June 30, 2015, and 27 MBbls/d for the six months ended June 30, 2015, primarily in the Wattenberg field due to continued horizontal drilling, partially offset by lower sales volumes due to the sale of certain EOR assets in April 2015.

• Southern and Appalachia Region sales volumes increased by 15 MBbls/d for the three and six months ended June 30, 2015, primarily in the Eagleford shale as a result of continued horizontal drilling, and in the Delaware basin due to increased drilling and wells brought online as a result of added infrastructure.

• Sales volumes in the Gulf of Mexico increased by 16 MBbls/d for the three months ended June 30, 2015, and 9 MBbls/d for the six months ended June 30, 2015, primarily from the Lucius development, which achieved first oil in January 2015.

• International sales volumes decreased by 17 MBbls/d for the three months ended June 30, 2015, and 4 MBbls/d for the six months ended June 30, 2015, due to the timing of cargo liftings in Algeria and the sale of the Company’s Chinese subsidiary in August 2014, partially offset by an increase in Ghana due to the timing of cargo liftings.

Anadarko’s average oil price received decreased for the three and six months ended June 30, 2015, as a result of global oversupply.

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Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues



2015Inc/(Dec)vs. 2014 2014 2015

Inc/(Dec)vs. 2014 2014

United StatesSales volumes—MMBbls 12 10% 11 24 23% 20

MBbls/d 130 10 119 134 23 109Price per barrel $ 17.98 (52) $ 37.39 $ 17.63 (56) $ 40.08InternationalSales volumes—MMBbls — NM — 1 NM —

MBbls/d 6 NM 1 6 NM 1Price per barrel $ 31.11 (53) $ 66.69 $ 32.01 (52) $ 66.69TotalSales volumes—MMBbls 12 13% 11 25 27% 20

MBbls/d 136 13 120 140 27 110Price per barrel $ 18.50 (51) $ 37.66 $ 18.24 (55) $ 40.22Natural-gas liquids sales revenues (millions) $ 229 (44) $ 411 $ 461 (42) $ 797

_________________________________________________________________________

NM—not meaningful

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. The Company’s NGLs sales volumes increased by 16 MBbls/d for the three months ended June 30, 2015, and 30 MBbls/d for the six months ended June 30, 2015.

• Sales volumes in the Rockies increased by 7 MBbls/d for the three months ended June 30, 2015, and 19 MBbls/d for the six months ended June 30, 2015, primarily in the Wattenberg field due to continued horizontal drilling and the Lancaster plant coming online in April 2014.

• Sales volumes in the Southern and Appalachia Region increased by 3 MBbls/d for the three months ended June 30, 2015, and 5 MBbls/d for the six months ended June 30, 2015, as a result of continued horizontal drilling in the Eagleford shale.

• International NGLs sales volumes increased by 5 MBbls/d for the three and six months ended June 30, 2015, as volumes have increased in Algeria since the commencement of sales at the Company’s El Merk facility during the second quarter of 2014.

Anadarko’s average NGLs price received decreased for the three and six months ended June 30, 2015, primarily due to decreased propane prices as a result of lower seasonal demand, higher NGLs production levels, and declines in oil prices.

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Gathering, Processing, and Marketing

Three Months Ended


June 30,

millions except percentages 2015Inc/(Dec)vs. 2014 2014 2015

Inc/(Dec)vs. 2014 2014

Gathering, processing, and marketing sales $ 305 10% $ 278 $ 598 2% $ 589Gathering, processing, and marketing expense 255 2 250 509 1 502Total gathering, processing, and marketing, net $ 50 79 $ 28 $ 89 2 $ 87

Gathering and processing sales includes revenue from the sale of NGLs and remaining residue gas extracted from natural gas purchased from third parties and processed by Anadarko, as well as fee revenue earned by providing gathering, processing, compression, and treating services to third parties. Marketing sales include the margin earned from purchasing and selling third-party oil and natural gas. Gathering, processing, and marketing expense includes the cost of third-party natural gas purchased and processed by Anadarko, as well as other operating and transportation expenses related to the Company’s costs to perform gathering, processing, and marketing activities.

Gathering, processing, and marketing, net increased by $22 million for the three months ended June 30, 2015, primarily resulting from higher gathering and processing revenue due to increased volumes. The increased processing volumes primarily related to WES’s November 2014 acquisition of Nuevo Midstream, LLC, which was renamed to Delaware Basin Midstream, LLC after the acquisition. Gathering, processing, and marketing, net was relatively flat for the six months ended June 30, 2015, due to higher gathering revenue related to higher throughput volumes offset by lower marketing margins from lower natural-gas and NGLs prices and higher operating expenses related to utilities.

Gains (Losses) on Divestitures and Other, net

Three Months Ended


June 30,millions 2015 2014 2015 2014Gains (losses) on divestitures and other, net $ (1) $ 54 $ (265) $ 1,560

For the three months ended June 30, 2015 gains (losses) on divestitures and other, net decreased by $55 million.

• The Company recognized a loss of $97 million on assets held for sale during the three months ended June 30, 2015. The loss was associated with the agreement to divest certain U.S. onshore oil and gas exploration and production properties and related midstream assets in East Texas for a sales price of $440 million, subject to closing adjustments. The sale is expected to close in the third quarter of 2015.

• The Company recognized income of $63 million in 2015 related to the settlement of a royalty lawsuit associated with a property in the Gulf of Mexico.

• The remaining decrease relates to lower minerals revenues and other revenues.

For the six months ended June 30, 2015 gains (losses) on divestitures and other, net decreased by $1.8 billion.

• The Company recognized losses of $437 million on divestitures and assets held for sale in 2015. These losses were comprised of the $97 million loss on properties in East Texas and a loss of $340 million associated with certain EOR assets in the Rockies.

• The Company recognized income of $117 million in 2015 related to the settlement of a royalty lawsuit associated with a property in the Gulf of Mexico.

• The Company recognized a $1.5 billion gain in the first quarter of 2014 associated with its divestiture of a 10% working interest in Offshore Area 1 in Mozambique for sales proceeds of $2.64 billion.

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Costs and Expenses

Three Months Ended


June 30,

2015Inc/(Dec)vs. 2014 2014 2015

Inc/(Dec)vs. 2014 2014

Oil and gas operating (millions) $ 226 (17)% $ 273 $ 522 (11)% $ 586Oil and gas operating—per BOE 2.93 (17) 3.53 3.24 (16) 3.88Oil and gas transportation and other (millions) 289 3 281 650 19 547Oil and gas transportation and other—per BOE 3.75 3 3.64 4.03 11 3.62

_________________________________________________________________________

BOE—barrel of oil equivalent

Oil and gas operating expense decreased by $47 million for the three months ended June 30, 2015, due to lower expenses of $26 million related to the sale of certain EOR assets in April 2015, $16 million related to the sale of the Company’s Chinese subsidiary in August 2014, and $12 million of lower workover costs due to reduced activity primarily in the Southern and Appalachia Region and in the Rockies, partially offset by higher costs of $12 million associated with increased workovers in Ghana.

Oil and gas operating expense decreased by $64 million for the six months ended June 30, 2015, due to lower workover costs of $47 million as a result of reduced activity primarily in the Gulf of Mexico and the Rockies, lower expenses of $32 million related to the divestiture of the Company’s Chinese subsidiary in August 2014, and $27 million related to the divestiture of certain EOR assets in April 2015, partially offset by higher costs of $38 million associated with increased workovers in Ghana.

The related per BOE costs decreased by $0.60 for the three months ended June 30, 2015, and $0.64 for the six months ended June 30, 2015, primarily due to the lower costs and asset sales discussed above as well as increased sales volumes for the six months ended June 30, 2015.

Oil and gas transportation and other expense increased by $8 million for the three months ended June 30, 2015, and $103 million for the six months ended June 30, 2015, primarily attributable to higher volumes associated with the growth in the Rockies. In addition, oil and gas transportation and other expense increased for the six months ended June 30, 2015, due to a $50 million expense for the early termination of a drilling rig.

Oil and gas transportation and other expense per BOE increased by $0.11 for the three months ended June 30, 2015, due to higher costs. Oil and gas transportation and other expense per BOE increased by $0.41 for the six months ended June 30, 2015, as higher costs were only partially offset by increased sales volumes. Oil and gas transportation and other expense per BOE for the six months ended June 30, 2015, included $0.31 related to the early termination of the drilling rig.

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Three Months Ended


June 30,millions 2015 2014 2015 2014Exploration ExpenseDry hole expense $ 13 $ 302 $ 42 $ 423Impairments of unproved properties 18 109 998 186Geological and geophysical expense 16 37 38 80Exploration overhead and other 56 54 108 112Total exploration expense $ 103 $ 502 $ 1,186 $ 801

For the three months ended June 30, 2015, total exploration expense decreased by $399 million.

• Dry hole expense decreased by $289 million due to unsuccessful drilling activities expensed in 2014 primarily associated with wells in the Gulf of Mexico.

• Impairments of unproved properties decreased $91 million due to 2014 impairments of $54 million primarily related to the expiration of leases in the Gulf of Mexico and $33 million as a result of changes in the Company’s drilling plans for certain U.S. onshore oil and gas properties.

• Geological and geophysical expense decreased by $21 million due to lower seismic purchases in Colombia, New Zealand, and Côte d’Ivoire.

For the six months ended June 30, 2015, total exploration expense increased by $385 million.

• Impairments of unproved properties increased by $812 million primarily due to a $935 million impairment in the first quarter of 2015 related to the Company’s unproved Greater Natural Buttes properties as a result of lower commodity prices. The Company recognized a $50 million impairment in the first quarter of 2014 due to the decision not to pursue further drilling in Sierra Leone in addition to the impairments in the Gulf of Mexico and for certain U.S. onshore oil and gas properties discussed above.

• Dry hole expense decreased by $381 million due to unsuccessful drilling activities expensed in 2014 primarily associated with wells in the Gulf of Mexico and New Zealand, compared to unsuccessful drilling activities expensed in 2015 primarily associated with a well in Mozambique.

• Geological and geophysical expense decreased by $42 million due to lower seismic purchases in Côte d’Ivoire, Colombia, and the Gulf of Mexico.

Three Months Ended


June 30,


Inc/(Dec)vs. 2014 2014

General and administrative $ 278 (9)% $ 305 $ 588 (2)% $ 603Depreciation, depletion, and amortization 1,214 16 1,048 2,470 14 2,172Other taxes 151 (58) 361 333 (51) 675Impairments 30 (74) 117 2,813 NM 120

General and administrative expense (G&A) decreased by $27 million for the three months ended June 30, 2015, and $15 million for the six months ended June 30, 2015, due to lower legal and consulting fees primarily as a result of the Tronox settlement reached in 2014. The decrease in G&A expense for the six months ended June 30, 2015, was partially offset by increased pension plan expenses as a result of changes in interest rates and higher employee headcount.

Depreciation, depletion, and amortization (DD&A) expense increased by $166 million for the three months ended June 30, 2015, primarily due to costs associated with U.S. onshore properties and additional gathering and processing facilities and increased asset retirement costs for wells in the Gulf of Mexico.

DD&A expense increased by $298 million for the six months ended June 30, 2015, primarily due to costs associated with U.S. onshore properties and additional gathering and processing facilities and higher 2015 sales volumes associated with U.S. onshore properties.

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Other taxes decreased by $210 million for the three months ended June 30, 2015, primarily due to lower U.S. severance taxes of $85 million, lower Algerian exceptional profits taxes of $76 million, and lower ad valorem taxes of $42 million. These decreases were primarily caused by lower commodity prices and lower sales volumes in Algeria.

For the six months ended June 30, 2015, other taxes decreased by $342 million primarily due to lower U.S. severance taxes of $145 million, lower Algerian exceptional profits taxes of $109 million, and lower ad valorem taxes of $62 million. These decreases were primarily caused by lower commodity prices. Also, Chinese windfall profits taxes decreased by $24 million for the six months ended June 30, 2015, as a result of the sale of the Company’s Chinese subsidiary in August 2014.

Impairment expense for the six months ended June 30, 2015, included $2.3 billion related to the Company’s Greater Natural Buttes oil and gas properties and $449 million for related midstream properties, which were impaired due to lower commodity prices. Impairment expense for the three and six months ended June 30, 2014, included $115 million related to an oil and gas property in the Gulf of Mexico that was impaired due to a reduction in estimated future cash flows.

Three Months Ended


June 30,millions 2015 2014 2015 2014Deepwater Horizon settlement and related costs $ — $ 93 $ 4 $ 93

Deepwater Horizon settlement and related costs for the three and six months ended June 30, 2015, included legal fees and other costs associated with the Deepwater Horizon event-related claims. In the second quarter of 2014, the Company recorded a $90 million expense and contingent liability associated with potential civil penalties under the Clean Water Act (CWA) related to the Deepwater Horizon event-related claims. For additional information, see Note 12—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Other (Income) Expense

Three Months Ended


June 30,millions except percentages 2015 2014 2015 2014Interest ExpenseDebt and other $ 244 $ 233 $ 498 $ 473Capitalized interest (43) (47) (81) (104)Total interest expense $ 201 $ 186 $ 417 $ 369

Interest expense increased by $15 million for the three months ended June 30, 2015, and $48 million for the six months ended June 30, 2015, primarily due to a decrease in capitalized interest related to lower construction-in-progress balances for long-term capital projects and an increase in interest expense due to higher debt outstanding during 2015.

Three Months Ended


June 30,millions 2015 2014 2015 2014(Gains) Losses on Derivatives, net(Gains) losses on commodity derivatives, net $ 1 $ 164 $ (52) $ 379(Gains) losses on interest-rate derivatives, net (312) 159 (107) 397Total (gains) losses on derivatives, net $ (311) $ 323 $ (159) $ 776

(Gains) losses on derivatives, net represents the changes in fair value of the Company’s derivative instruments as a result of changes in commodity prices and interest rates. Anadarko enters into commodity derivatives to manage the risk of changes in the market prices for its anticipated sales of production. Anadarko also enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to interest-rate changes. For additional information, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Three Months Ended


June 30,millions 2015 2014 2015 2014Other (Income) Expense, netInterest income $ (2) $ (4) $ (7) $ (7)Other 17 (9) 69 (5)Total other (income) expense, net $ 15 $ (13) $ 62 $ (12)

Other expense, net increased by $28 million for the three months ended June 30, 2015, primarily due to lower income associated with certain equity investments as a result of lower commodity prices.

Other expense, net increased by $74 million for the six months ended June 30, 2015, primarily due to lower income of $32 million associated with certain equity investments as a result of lower commodity prices and $30 million due to changes in foreign currency gains/losses, which reflect the unfavorable impact of exchange-rate changes primarily applicable to foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil. Also, as a result of a Chapter 11 bankruptcy declaration by a third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of a production facility and related wells, previously sold to the third party. The Company accrued the costs to decommission the facility and the wells in prior years. During the six months ended June 30, 2015, the Company recognized a charge of $22 million for the required decommissioning of an additional well. Anadarko has completed the decommissioning of the facility and expects to complete the remaining decommissioning of the wells in 2016.



millions 2015 2014 2015 2014Tronox-related contingent loss $ — $ 19 $ 5 $ 4,319

In April 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) entered into a settlement agreement for $5.15 billion, plus interest, resolving all claims asserted in the Tronox Adversary Proceeding. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective.

Anadarko recognized a Tronox-related contingent loss of $4.3 billion during the six months ended June 30, 2014, settlement-related interest expense of $19 million for the three and six months ended June 30, 2014, and additional settlement-related interest expense of $5 million until the settlement payment was made in late January 2015. See Note 12—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Income Tax Expense

Three Months Ended


June 30,millions except percentages 2015 2014 2015 2014Income tax expense (benefit) $ 77 $ 428 $ (1,315) $ 1,092Income (loss) before income taxes 185 694 (4,443) (1,268)Effective tax rate 42% 62% 30% (86)%

The increase from the 35% U.S. federal statutory rate for the three months ended June 30, 2015 and 2014, was primarily attributable to the tax impact from foreign operations and Algerian exceptional profits taxes. The increase from the 35% U.S. federal statutory rate for the three months ended June 30, 2014, was also attributable to net changes in uncertain tax positions and the non-deductible contingent CWA-penalty accrual.

The Company reported a loss before income taxes for the six months ended June 30, 2015 and 2014. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 2015, was primarily attributable to Algerian exceptional profit taxes and the tax impact from foreign operations. The variation from the 35% U.S. federal statutory rate for the six months ended June 30, 2014, was primarily attributable to net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding, the tax impact from foreign operations, Algerian exceptional profits taxes, and the non-deductible contingent CWA-penalty accrual.

For additional information on income taxes, see Note 13—Income Taxes in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Net Income Attributable to Noncontrolling Interests

The Company’s net income attributable to noncontrolling interests for the three and six months ended June 30, 2015 and 2014, related to public ownership interests in WES and WGP. Public ownership in WES consisted of a limited partnership interest of 55.2% at June 30, 2015, and 56.8% at June 30, 2014. Public ownership in WGP consisted of a limited partnership interest of 12.7% at June 30, 2015, and 9.0% at June 30, 2014. In June 2015, Anadarko issued 9.2 million TEUs, which include an equity component that may be settled in WGP common units. See Note 7—Tangible Equity Units and Note 11—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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OPERATING RESULTS

Segment Analysis—Adjusted EBITDAX To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; exploration expense; DD&A; impairments; interest expense; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; and certain items not related to the Company’s normal operations, less net income attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included Deepwater Horizon settlement and related costs, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX, which is not a GAAP measure, excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.

Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders. Adjusted EBITDAX as defined by Anadarko may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures prepared in accordance with GAAP, such as operating income or cash flows from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect net income (loss) attributable to common stockholders and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Anadarko’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes, and consolidated Adjusted EBITDAX by reporting segment.

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Adjusted EBITDAX

Three Months Ended


June 30,


Inc/(Dec)vs. 2014 2014

Income (loss) before income taxes $ 185 (73)% $ 694 $ (4,443) NM $ (1,268)Exploration expense 103 (79) 502 1,186 48 % 801DD&A 1,214 16 1,048 2,470 14 2,172Impairments 30 (74) 117 2,813 NM 120Interest expense 201 8 186 417 13 369Total (gains) losses on derivatives, net, less net

cash from settlement of commodity derivatives (229) (197) 237 14 (98) 600Deepwater Horizon settlement and related costs — (100) 93 4 (96) 93Tronox-related contingent loss — (100) 19 5 (100) 4,319Certain other nonoperating items — NM — 22 NM —Less net income attributable to noncontrolling

interests 47 21 39 79 (4) 82Consolidated Adjusted EBITDAX $ 1,457 (49) $ 2,857 $ 2,409 (66) $ 7,124Adjusted EBITDAX by reporting segment

Oil and gas exploration and production $ 1,314 (56)% $ 2,997 $ 2,161 (71)% $ 7,387Midstream 216 40 154 420 32 317Marketing (56) (19) (47) (103) (20) (86)Other and intersegment eliminations (17) 93 (247) (69) 86 (494)

Oil and Gas Exploration and Production Adjusted EBITDAX decreased for the three and six months ended June 30, 2015, due to lower commodity prices, partially offset by higher oil and NGLs sales volumes. Adjusted EBITDAX also decreased for the six months ended June 30, 2015, due to a $1.5 billion gain associated with the Company’s 2014 divestiture of a 10% working interest in Offshore Area 1 in Mozambique and a $340 million loss on assets held for sale associated with the divestiture of certain EOR assets in the Rockies in April 2015.

Midstream Adjusted EBITDAX increased for the three and six months ended June 30, 2015, primarily due to higher gathering revenue resulting from higher volumes.

Marketing Marketing earnings primarily represent the margin earned on sales of natural gas, oil, and NGLs purchased from third parties. Adjusted EBITDAX decreased for the three and six months ended June 30, 2015, due to lower marketing margins.

Other and Intersegment Eliminations Other and intersegment eliminations consists primarily of corporate costs, income from hard-minerals royalties, and net cash from settlement of commodity derivatives. Adjusted EBITDAX increased for the three and six months ended June 30, 2015, primarily due to a favorable change in net cash received/paid on the settlement of commodity derivatives in 2015.

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LIQUIDITY AND CAPITAL RESOURCES

Overview Anadarko generates cash needed to fund capital expenditures, debt-service obligations, and dividend payments primarily from operating activities, and enters into debt and equity transactions primarily to maintain the Company’s desired capital structure and to finance acquisition opportunities. The Company has a variety of funding sources available, including cash on hand, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through divestitures and joint-venture arrangements that reduce future capital expenditures, and the Company’s credit facilities and commercial paper program. In addition, an effective registration statement is available to Anadarko covering the sale of 32 million WGP common units owned by the Company at June 30, 2015. For additional information, see Sources of Cash—Financing Activities below.

During the six months ended June 30, 2015, cash from operations and cash on hand were the primary sources for funding capital investments. Anadarko’s cash flows used in operating activities included a $5.2 billion payment related to the Tronox settlement, which was funded using cash on hand and borrowings. The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions.

At June 30, 2015, Anadarko’s scheduled debt maturities during the next year consist of $592 million of borrowings under the commercial paper program and $33 million related to the senior amortizing notes associated with the TEUs as discussed in Sources of Cash—Financing Activities below. The Company classified the outstanding commercial paper notes as long-term debt on the Company’s Consolidated Balance Sheet, as the Company currently intends to refinance these obligations at maturity with additional commercial paper notes supported by the Company’s Five-Year Facility. In addition, the Company’s $1.750 billion 5.950% Senior Notes are scheduled to mature in September 2016. The Company has the ability and intent to refinance these notes with long-term debt.

Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $796 million at the next put date in October 2015. The Zero Coupons are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt.

Management believes that the Company’s liquidity position, asset portfolio, and operating and financial performance provide the necessary financial flexibility to fund the Company’s current and long-term operations.

Revolving Credit Facilities and Commercial Paper Program In January 2015, upon satisfaction of certain conditions, including the settlement payment related to the Tronox Adversary Proceeding, the Company’s $5.0 billion senior secured revolving credit facility was replaced by a $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility), which is expandable to $4.0 billion, and a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility). At June 30, 2015, the Company had no outstanding borrowings under the Five-Year or 364-Day Facilities and was in compliance with all covenants therein.

During the first quarter of 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Company’s Five-Year Facility. At June 30, 2015, the Company had $592 million of commercial paper notes outstanding at a weighted-average interest rate of 0.51%. During the six months ended June 30, 2015, maximum outstanding borrowings under the commercial paper program were $1.4 billion. The average borrowings outstanding under the commercial paper program were $1.0 billion with a weighted-average interest rate of 0.62%.

For additional information on the revolving credit facilities and the commercial paper program, see Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

WES Funding Sources WES, Anadarko’s publicly traded consolidated subsidiary, uses cash flows from operations to fund ongoing operations, service its debt, and make distributions to its equity holders. As needed, WES supplements cash generated from its operating activities with proceeds from debt or equity issuances or borrowings under its five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which is expandable to $1.5 billion.

At June 30, 2015, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $270 million at an interest rate of 1.49%, had outstanding letters of credit of $13 million, and had available borrowing capacity of $917 million. See Sources of Cash—Financing Activities below.

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During the six months ended June 30, 2015, WES issued 874 thousand of its common units to the public under its continuous offering program, which allows the issuance of up to an aggregate of $500 million of WES common units, raising net proceeds of $57 million. The remaining amount available under this program was $443 million of WES common units at June 30, 2015.

Sources of Cash

Operating Activities Anadarko’s cash flow used in operating activities during the six months ended June 30, 2015, was $3.3 billion, compared to cash flow provided by operating activities of $4.2 billion for the same period of 2014. The decrease is primarily due to the $5.2 billion Tronox settlement payment, decreased sales revenues resulting from lower commodity prices, and the unfavorable impact of changes in working capital items.

One of the primary sources of variability in the Company’s cash flows from operating activities is fluctuations in commodity prices, the impact of which Anadarko partially mitigates by entering into commodity derivatives. Sales-volume changes also impact cash flow, but historically have not been as volatile as commodity prices. Anadarko’s cash flows from operating activities are also impacted by the costs related to continuing operations and debt service.

Investing Activities During the six months ended June 30, 2015, Anadarko received pretax proceeds of $700 million primarily related to the April 2015 sale of certain EOR assets in the Rockies.

Financing Activities During the six months ended June 30, 2015, the Company borrowed $1.8 billion under the 364-Day Facility, which was primarily used to repay $1.5 billion of borrowings entered into in January 2015 under its $5.0 billion senior secured revolving credit facility. The remaining proceeds were used for partial payment of the settlement related to the Tronox Adversary Proceeding and for general corporate purposes. The Company also had net borrowings of $629 million of commercial paper notes and sold 2.3 million WGP common units to the public, raising net proceeds of $130 million, with proceeds from both used for general corporate purposes.

During the second quarter of 2015, Anadarko issued 9.2 million TEUs at a stated amount of $50.00 per TEU, raising net proceeds of $446 million. Each TEU is comprised of a prepaid equity purchase contract for WGP common units, subject to Anadarko’s right to elect to issue and deliver shares of Anadarko’s common stock in lieu of WGP common units, and a senior amortizing note due in June 2018, which bears interest at the rate of 1.50% per annum. For additional information, see Note 7—Tangible Equity Units in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Anadarko’s consolidated subsidiary, WES, borrowed $280 million under its RCF primarily for general partnership purposes, including the funding of capital expenditures. In addition, during the second quarter of 2015, WES completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025. Net proceeds from the offering were used to repay a portion of the borrowings under WES’s RCF. WES also issued 874 thousand of its common units to the public under its continuous offering program, raising net proceeds of $57 million.

Uses of Cash

Anadarko invests significant capital to develop, acquire, and explore for oil and natural gas and to expand its midstream infrastructure. The Company also uses cash to fund ongoing operating costs, capital contributions for equity investments, debt repayments, and distributions to its shareholders.

Tronox Settlement Payment In April 2014, Anadarko and Kerr-McGee entered into a settlement agreement to resolve all claims asserted in the Tronox Adversary Proceeding for $5.15 billion. In addition, the Company agreed to pay interest on that amount from April 3, 2014, through payment of the settlement. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective. See Note 12—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Capital Expenditures The following presents the Company’s capital expenditures by category:

Six Months Ended

June 30,millions 2015 2014Property acquisitions

Exploration $ 53 $ 92Development 1 112

Exploration 382 786Development 2,224 3,149Capitalized interest 68 93

Total oil and gas capital expenditures 2,728 4,232Gathering, processing, and marketing and other (1) 495 738Total capital expenditures (2) $ 3,223 $ 4,970

________________________________________________________________________________________

(1) Includes WES capital expenditures of $278 million for the six months ended June 30, 2015, and $343 million for the six months ended June 30, 2014.

(2) Capital expenditures in this table are presented on an accrual basis. Additions to properties and equipment on the Company’s Consolidated Statements of Cash Flows only include capital expenditures funded with cash payments during the period.

The Company’s capital spending decreased by $1.7 billion for the six months ended June 30, 2015, due to decreased development costs of $925 million primarily in the Rockies and the Southern and Appalachia Region and lower exploration costs of $404 million primarily in the Gulf of Mexico and the Southern and Appalachia Region. Also, development acquisitions in 2014 included a spar lease buyout of $110 million in the Gulf of Mexico and gathering, processing, and marketing and other decreased $243 million primarily due to lower expenditures for plants and gathering in the Rockies.

In the third quarter of 2014, the Company entered into a carried-interest arrangement that requires a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Eaglebine development, located in Southeast Texas. The third-party funding is expected to cover Anadarko’s future capital costs in the development through 2020. At June 30, 2015, $61 million of the total $442 million obligation had been funded.

In the second quarter of 2013, the Company entered into a carried-interest arrangement that requires a third-party partner to fund $860 million of Anadarko’s capital costs in exchange for a 12.75% working interest in the Heidelberg development, located in the Gulf of Mexico. The third-party funding is expected to cover the substantial majority of Anadarko’s expected future capital costs through first production, which is expected to occur by mid-2016. At June 30, 2015, $592 million of the total $860 million obligation had been funded.

Investments During the six months ended June 30, 2015, the Company made capital contributions of $68 million for equity investments, which are included in Other—net under Investing Activities in the Consolidated Statements of Cash Flows. These contributions were primarily associated with joint ventures for a gas processing plant, marine well containment, and pipelines.

Debt Retirements and Repayments During the six months ended June 30, 2015, the Company repaid $1.5 billion of borrowings under the $5.0 billion senior secured revolving credit facility, $1.8 billion under the 364-Day Facility, and $37 million of commercial paper notes with maturities greater than 90 days. WES also repaid $520 million of borrowings under its RCF primarily from proceeds from WES’s debt offering.

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Derivative Instruments The Company’s derivative instruments are subject to individually negotiated credit provisions that may require the Company or the counterparties to provide collateral of cash or letters of credit depending on the derivative portfolio valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered, such as if the Company’s credit rating from major credit rating agencies declines to below investment grade. The Company provided cash collateral of $100 million as of June 30, 2015, in connection with its derivative instruments. Also, the Company has $1.1 billion of interest rate derivatives scheduled to settle in September 2016, unless the terms of the derivatives are amended.

Common Stock Dividends and Distributions to Noncontrolling Interest Owners Anadarko paid dividends of $277 million to its common stockholders during the six months ended June 30, 2015, and $230 million during the six months ended June 30, 2014. During the second quarter of 2014, Anadarko increased the quarterly dividend paid to common stockholders from $0.18 per share to $0.27 per share. Anadarko has paid a dividend to its common stockholders on a quarterly basis since becoming a public company in 1986. The amount of future dividends paid to Anadarko common stockholders will be determined by the Board of Directors on a quarterly basis and will depend on earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors.

WES distributed to its unitholders other than Anadarko and WGP an aggregate of $111 million during the six months ended June 30, 2015, and $83 million during the six months ended June 30, 2014. WES has made quarterly distributions to its unitholders since its initial public offering in the second quarter of 2008, and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.75 per common unit for the second quarter of 2015 (to be paid in August 2015).

WGP distributed to its unitholders other than Anadarko an aggregate of $17 million during the six months ended June 30, 2015, and $10 million during the six months ended June 30, 2014. WGP has made quarterly distributions to its unitholders since its initial public offering in December 2012, and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.36375 per unit for the second quarter of 2015 (to be paid in August 2015).

Outlook

The Company’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly dependent on the prices the Company receives for oil, natural gas, and NGLs, which can fluctuate significantly. During the last 12 months, New York Mercantile Exchange West Texas Intermediate oil prices have been volatile and ranged from a high of $105.34 per barrel in July 2014 to a low of $43.46 in March 2015. New York Mercantile Exchange Henry Hub natural-gas prices have also been volatile and ranged from a high of $4.49 per MMBtu in November 2014 to a low of $2.49 in April 2015. The duration and magnitude of the decline in oil and natural-gas prices cannot be predicted.

The Company has a deep portfolio of investment opportunities and the financial strength and operational flexibility to move capital spending from areas focused on near-term production growth to areas focused on longer-term growth where anticipated returns are less sensitive to spot oil and natural-gas prices. The recent decline in oil prices resulted in the Company significantly reducing its capital expenditures in 2015 compared to 2014. The Company will continue to evaluate the oil and natural-gas price environments and may adjust its capital spending plans as prices fluctuate while maintaining appropriate liquidity and financial flexibility.

The Company is committed to the execution of its worldwide exploration, appraisal, and development programs. The Company estimates a 2015 capital spending range of $6.0 billion to $6.4 billion. This amount includes approximately $630 million to $690 million of WES capital expenditures, excluding any acquisitions made by WES. The Company has currently allocated approximately 65% of its 2015 capital spending budget to development activities, 15% to exploration activities, and 20% to gathering and processing activities and other business activities. The Company currently expects its 2015 capital spending by area to be approximately 55% for the U.S. onshore region and Alaska, 10% for the Gulf of Mexico, 20% for Midstream and other, and 15% for International.

Anadarko believes that its cash on hand, available borrowing capacity, and expected level of operating cash flows will be sufficient to fund the Company’s projected operational and capital programs for 2015 and continue to meet its other current obligations. The Company’s cash on hand is available for use and could be supplemented, as needed, with available borrowing capacity under the 364-Day Facility, Five-Year Facility, and commercial paper program. The Company may also enter into carried-interest arrangements with third parties to fund certain capital expenditures, execute asset divestitures, and sell WGP common units that it owns in order to supplement cash flow.

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The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and evaluates available funding alternatives in light of current and expected conditions. To reduce commodity-price risk and increase the predictability of 2015 cash flows, Anadarko entered into strategic derivative positions covering approximately 37% of its remaining 2015 anticipated natural-gas sales volumes. In addition, the Company has derivative positions in place for 2016. See Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Recent Accounting Developments

See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. In addition, foreign-currency exchange-rate risk exists due to anticipated foreign-currency denominated payments and receipts. These risks can affect revenues and cash flows and the Company’s risk-management policies provide for the use of derivative instruments to manage these risks. Both exchange- and over-the-counter-traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

COMMODITY-PRICE RISK The Company’s most significant market risk relates to prices for natural gas, oil, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Company’s oil and gas properties or goodwill may be required if commodity prices experience a significant decline. The types of commodity derivative instruments used by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Below is a sensitivity analysis for the Company’s commodity-price-related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes The Company had derivative instruments in place to reduce the price risk associated with future production of 210 Bcf of natural gas and 10 MMBbls of oil at June 30, 2015, with a net derivative asset position of $124 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $76 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $67 million. However, any cash received or paid to settle these derivatives would be substantially offset by the sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes At June 30, 2015, the Company had a net derivative asset position of $11 million on outstanding derivative instruments entered into for trading purposes. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s gains or losses on these derivative instruments.

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INTEREST-RATE RISK Borrowings under each of the 364-Day Facility, the Five-Year Facility, the commercial paper program, and WES’s RCF are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheets has fixed interest rates. The Company has $2.9 billion of obligations based on the London Interbank Offered Rate (LIBOR) that are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two non-controlled entities. These obligations give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. While a 10% change in LIBOR would not materially impact the Company’s interest cost, it would affect fair value of outstanding fixed-rate debt.

At June 30, 2015, the Company had a net derivative liability position of $1.1 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would increase (decrease) the aggregate fair value of outstanding interest-rate swap agreements by $111 million. However, any change in the interest-rate derivative gain or loss could be substantially offset by changes in actual borrowing costs associated with future debt issuances. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

FOREIGN-CURRENCY EXCHANGE-RATE RISK Anadarko’s operating revenues are denominated in U.S. dollars, and the predominant portion of Anadarko’s capital and operating expenditures are also U.S.-dollar-denominated. Exposure to foreign-currency risk generally arises in connection with project-specific contractual arrangements and other commitments. Near-term foreign-currency-denominated expenditures are primarily in euros, Brazilian reais, British pounds sterling, Mozambican meticais, and Colombian pesos. Management periodically engages in various risk-management activities to mitigate a portion of its exposure to foreign-currency exchange-rate risk.

The Company has risk related to exchange-rate changes applicable to cash held in escrow pending final determination of the Company’s Brazilian tax liability for its 2008 divestiture of the Peregrino field offshore Brazil. The Brazilian tax matter is currently under consideration by the Brazilian courts. At June 30, 2015, cash of $110 million was held in escrow. A 10% increase or decrease in the foreign-currency exchange rate would not materially impact the Company’s gain or loss related to foreign currency.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that the information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of June 30, 2015.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the second quarter of 2015 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

GENERAL The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims; property damage claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s financial condition, results of operations, or cash flows.

WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the U.S. Environmental Protection Agency with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Granger, Wyoming facilities. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.

See Note 12—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference, for material developments with respect to matters previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and material matters that have arisen since the filing of such report.

Item 1A. Risk Factors

There have been no material changes from the risk factors included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following sets forth information with respect to repurchases by the Company of its shares of common stock during the second quarter of 2015.

Period

Total number of

shares purchased (1)

Averageprice paidper share

Total number ofshares purchasedas part of publiclyannounced plans

or programs

Approximate dollarvalue of shares that

may yet bepurchased under theplans or programs

April 1 - 30, 2015 3,051 $ 87.32 —May 1 - 31, 2015 3,313 $ 86.37 —June 1 - 30, 2015 3,779 $ 84.47 —Total 10,143 $ 85.95 — $ —

____________________________________________________________

(1) During the second quarter of 2015, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances.

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Item 6. Exhibits

Exhibits designated by an asterisk (*) are filed herewith or double asterisk (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing under File Number 1-8968 as indicated.

ExhibitNumber Description

3 (i) Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as Exhibit 3.3 to Form 8-K filed on May 22, 2009

(ii) By-Laws of Anadarko Petroleum Corporation, amended and restated as of May 11, 2015, filed as Exhibit 3.1 to Form 8-K filed on May 15, 2015

4 (i) Purchase Contract Agreement, dated June 10, 2015, between Anadarko Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on June 10, 2015

(ii) Trustee Indenture, dated as of September 19, 2006, Anadarko Petroleum Corporation to The Bank of New York Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on September 19, 2006

(iii) Third Supplemental Indenture dated as of June 10, 2015, between Anadarko Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., filed as Exhibit 4.2 to Form 8-K filed on June 10, 2015

(iv) Form of Unit (included in Exhibit 4.i)

(v) Form of Purchase Contract (included in Exhibit 4.i)

(vi) Form of Amortizing Note (included in Exhibit 4.iii)

* 10 (i) Anadarko Petroleum Corporation Key Employee Change of Control Contract, dated June 1, 2015, for Christopher O. Champion

* (ii) First Amendment to Time Sharing Agreement between R.A. Walker and Anadarko Petroleum Corporation, dated June 2, 2015

* 31 (i) Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer

* 31 (ii) Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer

** 32 Section 1350 Certifications

* 101 .INS XBRL Instance Document

* 101 .SCH XBRL Schema Document

* 101 .CAL XBRL Calculation Linkbase Document

* 101 .DEF XBRL Definition Linkbase Document

* 101 .LAB XBRL Label Linkbase Document

* 101 .PRE XBRL Presentation Linkbase Document

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ANADARKO PETROLEUM CORPORATION (Registrant)

July 28, 2015 By: /s/ ROBERT G. GWINRobert G. GwinExecutive Vice President, Finance and Chief Financial Officer

APC 2015 2Q - 10Q - SEC · Title: APC 2015 2Q - 10Q Created Date: 7/28/2015 1:50:00 PM

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Transcript of APC 2015 2Q - 10Q - SEC · Title: APC 2015 2Q - 10Q Created Date: 7/28/2015 1:50:00 PM